The recovery of oil from oil fields often requires injection of a displacing fluid, most often water, to maintain the pressure in the reservoir so as to allow production, through displacement of the oil in place, from injection wells to production wells arranged according to a previously optimized scheme for the field considered.
In the case of water injection, this displacing fluid can be injected alone or it can, on the contrary, contain chemical agents intended to improve sweeping of the oil in place.
Among these chemical agents, on the one hand, the surfactants are intended to reduce trapping of the oil in the pores of the rock through reduction of the water-oil interfacial tension and possibly modification of the rock wettability. On the other hand, polymers provide higher viscosity to the water, thus increasing its hydrocarbon phase sweep efficiency.
However, these two categories of enhancing products undergo losses in the reservoir due to many phenomena, among which retention or adsorption of the products on the rock, which can be high and obviously detrimental to the economic interest of such recovery methods. The presence of divalent cations in place in the reservoir water and on the rock minerals (notably clays) still increases these losses.
The most frequently used method for reducing surfactant or polymer adsorption is the injection of an alkaline additive, i.e. a base such as sodium carbonate or soda. It can in fact be shown that the adsorption of surfactants is very widely decreased to a basic pH. This effect is caused by the increase in absolute value of the (negative) surface charge of the rock due to the adsorption of the OH— ions. The basic pH is provided by the injection of the alkaline agent. In order to benefit from this effect in the surfactant injection method, one has to be able to calculate the pH value of the slug of chemical additives injected into the reservoir to limit adsorption of the surfactant.
These rock conditioning agents (alkaline agent), dissolved in various chemical forms, dissociated or not into ions, involve many chemical equilibria in aqueous phase:                salt precipitation reactions (divalent cation salts in place notably),        multiple interactions with the rock (ion exchange and adsorption with modification of the charges of the solid surface),        possibly also reactions with some constituents of the oil in place (formation of soaps with the surfactant). The injection of a conditioning agent alone can even already improve the recovery of oil in relation to the conventional injection of water without any chemical agent.        
All these physico-chemical phenomena have to be taken into account in order to determine the volumes and concentrations of the products to be injected, and the modes of injection (flow rates, distribution in the field via the injection scheme, etc.), for the reservoir rock conditioning phase (injection of alkaline conditioning agents) as well as for the subsequent enhanced water slugs (through surfactants and/or polymers), intended to improve the recovery and the displacement efficiency.
This dimensioning of the injected solutions is essential because it determines the feasibility and the profitability of these methods, via:
(a) the size and the cost of the facilities: surface facilities for preparing the solutions (surfactants, polymers); number and arrangement of well pumping equipments,
(b) the conditioning product and enhancer masses required (volumes and concentrations), therefore their cost,
(c) and, of course, the efficiency in terms of oil recovery.
The composition of the chemical formulation (aqueous solution of chemical additives comprising surfactants, alkaline agents and polymer) is determined by laboratory experiments and by a numerical calculation for extrapolation to the size of the reservoir.
The laboratory experiments consist in injecting a formulation of chemical additives into a previously prepared reservoir core so as to represent the state of oil saturation of the reservoir prior to starting the enhanced recovery operations. During the injection of the formulation of chemical additives into the core, oil is recovered. The amount of oil recovered depends on the nature and the concentration of the additives in the formulation and on the volume of solution injected.
Numerical modelling allows to optimize the implementation of the method and to extrapolate experiments from the laboratory scale to the reservoir scale. The modelling tool is a tool allowing to account for the flows in porous media on various scales. An example of a modelling tool is the PumaFlow model (IFP Energies nouvelles, France), which is a numerical modelling tool used by reservoir engineers. In reservoir models, the flow is a two-phase flow (water/oil). The oil and water equations are of <<black oil>> type. Transport equations for each chemical species in the water phase have to be added to these <<black oil>> equations. The transport is modelled by the equation of conservation of the chemical species in the water phase. The pH value of the solution is calculated from a relation between the concentration of the alkaline agent and the OH— concentration. The alkaline agent is either directly soda or a base allowing a buffer effect to be obtained.
In the case of a buffer alkaline agent, equilibrium relations have to be associated with the previous equations to calculate the OH— concentration, then the pH value from the concentration of the buffer alkaline agent. This method is described in the following references: Pope et al. SPE 110,212 (reaction 5 for carbonate) and Pope et al. SPE 116,754 (relations 3 and 4 for metaborate). The model for a buffer alkaline agent gives satisfactory results when compared with typical experimental results, as shown in FIG. 1 that illustrates the evolution of the pH value as a function of the pore volume (VP) injected. The dots represent the experimental measurements, the curve represents the <<buffer alkaline agent>> model.
However, taking account of the equilibrium relations increases the computation times. All the thermodynamic quantities associated with the chemical equilibria also have to be known, which is difficult in particular for sodium metaborate. Furthermore, there is a risk of introducing additional uncertainties that may lead to wrong calculated pH values, or even to difficulties as regards the solution of the numerical calculation and to computation stops. In some cases (when the reservoir model has a large number of cells, or when the chemical equilibria involving the alkaline agent and allowing the OH— concentration to be calculated are not all known), it is not possible to calculate the amount of alkaline agent to be injected to prevent retention of the surfactant. It is not possible to predict the oil recovery in the method that becomes impossible to apply.
The object of the invention is a method of modelling the evolution of the pH value of a porous medium after the injection of an alkaline agent solution into this medium, without applying the system of equations relative to the equilibrium relations for the transport of the buffer alkaline agent. According to this pH modelling method, the alkaline agent is considered as a soda pseudo-constituent, of concentration equal to the OH— concentration corresponding to the pH value of the alkaline agent solution injected. The modelling tools specific to the soda compound are then used. The method according to the invention allows to calculate the amount of alkaline agent to be injected in order to obtain a basic pH in the case of a model on the reservoir scale.